(1) See Non-GAAP Financial Measures.
(2) Based on the number of shares issued and outstanding at each record date.
(3) Weighted average number of shares outstanding during the period, basic.
(4) See Conversion of Natural Gas to Barrels of Oil Equivalent (boe).

President’s Message

With oil prices continuing to display strength, our funds from operations per share grew by 7% from Q1 to Q2 and we are forecasting an adjusted payout ratio for 2018 near the lower end of our target adjusted payout range of 60%-80%. We will continue to monitor commodity prices and allocate free cash flow in ways that maximize shareholder value.

On the activity front, drilling on our royalty lands came in slightly below expectations, however the second quarter typically represents a period of reduced activity. We are maintaining our 2018 production forecast between 11,750-12,250 boe/d and we continue to position Freehold as a high quality investment in oil and gas with low debt, sustainable dividends and an attractive yield.

Tom Mullane
President and CEO

Dividend Announcement

The Board has declared a dividend of $0.0525 per common share to be paid on September 17, 2018 to shareholders of record on August 31, 2018. The dividend is designated as an eligible dividend for Canadian income tax purposes.

2018 Second Quarter Highlights

Freehold delivered strong financial results in the second quarter of 2018. Highlights included:

Royalty interests accounted for 94% of total production and contributed 100% of operating income in Q2-2018, representing all-time highs for Freehold.

Funds from operations totaled $34.5 million, an increase of 9% compared to Q2-2017. Higher funds from operations was driven by better oil and natural gas liquids (NGL) prices and lower cash costs. On a per share basis, funds from operations was $0.29/share in Q2-2018 up from $0.27/share in both Q2-2017 and Q1-2018.

Freehold generated $15.1 million in free cash flow (1), over and above our dividend, which we applied to outstanding debt. At June 30, 2018, net debt totaled $77.9 million resulting in a net debt to 12-month trailing funds from operations ratio of 0.6 times.

Freehold closed a $2.7 million royalty acquisition in Q2-2018. The transaction included a 3% gross overriding royalty on a 21% working interest on the Mitsue Gilwood Sands Unit No. 1. Annualized 2018 production and operating income associated with this asset is estimated to be 16 bbl/d and $0.4 million.

Wells drilled on our royalty lands totaled 85 (1.2 net) in the quarter compared to 58 (1.6 net) in Q2-2017. The second quarter typically represents a period of slower drilling on our lands as spring break-up occurs, slowing operations. For the year, 324 gross (7.6 net) wells have been drilled.

In Q2-2018, Freehold issued 18 new lease agreements with 10 companies, compared to 42 issued in Q1-2018 and 12 leases in Q2-2017, highlighting the success of our leasing team. Year-to-date (YTD) we have completed 60 new lease agreements on our royalty lands. Since the inception of our leasing team in January 2017 we have completed 161 new lease agreements.

Cash costs (1) for the quarter totaled $5.17/boe, down from $5.63/boe in Q2-2017. For 2018, we are forecasting cash costs of approximately $5.00/boe.

Dividends declared for Q2-2018 totaled $0.1575 per share, up 5% versus the previous year. In March 2018, Freehold announced an increase to its monthly dividend from $0.05 to $0.0525 per share commencing in April 2018.

Basic payout ratio (1) (dividends declared/funds from operations) for Q2-2018 totaled 54% while the adjusted payout ratio (1) ((cash dividends plus capital expenditures)/funds from operations) for the same period was 56%.
(1) See Non-GAAP Financial Measures.

Royalty Drilling

Including drilling associated with acquisitions and unit wells, 324 (7.6 net) wells were drilled on our royalty lands during the first six months of 2018. This represents an increase of 56% on gross wells but a decrease of 25% on net wells versus the same period in 2017. While the second quarter typically represents a period of slowed activity, we saw even lower drilling activity than expected.

Activity through the first six months of 2018 was primarily focused on Saskatchewan oil prospects, including Viking at Dodsland, Mississippian plays in southeast Saskatchewan, and Shaunavon and Cantuar in southwest Saskatchewan. Together, Saskatchewan and Manitoba wells represented approximately 60% of our gross non-unit drilling through the quarter. Alberta activity has been concentrated in the Cardium, with strong drilling on our newly acquired Pembina Cardium acreage. Drilling for Deep Basin Spirit River, Ellerslie and Montney remains positive, along with Mannville Oil drilling in eastern Alberta. Our top payors continue to represent some of the most well capitalized E&P companies in Canada.

Royalty Interest Drilling

Three Months Ended June 30

Six Months Ended June 30

2018

2017

2018

2017

Equivalent

Equivalent

Equivalent

Equivalent

Gross

Net (1)

Gross

Net (1)

Gross

Net (1)

Gross

Net (1)

Non-unitized wells

24

1.0

35

1.5

168

7.0

175

10.0

Unitized wells (2)

61

0.2

23

0.1

156

0.6

33

0.2

Total

85

1.2

58

1.6

324

7.6

208

10.2

(1) Equivalent net wells are the aggregate of the number obtained by multiplying each gross well by our royalty interest percentage.
(2) Unitized wells are in production units wherein we generally have small royalty interests in hundreds of wells.

2018 Guidance Update

Below are details of some of the changes made to our key operating assumptions for 2018 based on results for the first half of the year and expectations for the remainder of the year.

We are maintaining our 2018 average production range of 11,750-12,250 boe/d. Volumes are expected to be weighted approximately 54% oil and NGL and 46% natural gas (previously 55% and 45% respectively). We continue to maintain our royalty focus with royalty production accounting for 94% of forecasted 2018 production and 99% of operating income.

As part of continued weakness in equity markets and depressed prices associated with natural gas we reduced our 2018 drilling forecast from 25 to 20 net wells.

Our AECO natural gas price assumption remains unchanged at $1.75/mcf. Even though market prices are slightly lower, there have been significant AECO price fluctuations, so a change was not yet justified.

We have increased our forecast year-end net debt to funds from operations to approximately 0.4 times (from 0.3 times) due to acquisitions completed YTD, changes in working capital and a slight increase in gas production relative to oil production.

Key Operating Assumptions

Guidance Date

2018 Annual Average

Aug 2, 2018

May 9, 2018

Mar. 8, 2018

Total daily production

boe/d

11,750-12,250

11,750-12,250

11,750-12,250

West Texas Intermediate crude oil

US$/bbl

65.00

65.00

60.00

Edmonton Light Sweet crude oil

Cdn$/bbl

76.00

76.00

N/A

Western Canadian Select crude oil

Cdn$/bbl

55.00

53.00

45.00

AECO natural gas

Cdn$/Mcf

1.75

1.75

2.00

Exchange rate

Cdn$/US$

0.77

0.79

0.80

Operating costs

$/boe

1.45

1.45

1.45

General and administrative costs (1)

$/boe

2.50

2.50

2.50

Weighted average shares outstanding

millions

118

118

118

(1) Excludes share based compensation.

Recognizing the cyclical nature of the oil and gas industry, we continue to closely monitor commodity prices and industry trends for signs of changing market conditions. We caution that it is inherently difficult to predict activity levels on our royalty lands since we have no operational control. As well, significant changes (positive or negative) in commodity prices (including Canadian oil price differentials), foreign exchange rates, or production rates may result in adjustments to the dividend rate.

Based on our current guidance and commodity price assumptions, and assuming no significant changes in the current business environment, we expect to maintain the current monthly dividend rate through the next quarter. We will continue to evaluate the commodity price environment and adjust the dividend levels as necessary (subject to the quarterly review and approval of our Board of Directors).

Conference Call Details

A conference call to discuss financial and operational results for the period ended June 30, 2018 will be held for the investment community on Friday, August 3, 2018 beginning at 7:00 am MT (9:00 am ET). To participate in the conference call, approximately 10 minutes prior to the conference call, please dial 1-800-806-5484 (toll-free in North America), participant access code 6624442#.

Availability on SEDAR

Freehold’s 2018 second quarter interim unaudited condensed consolidated financial statements and accompanying Management’s Discussion and Analysis (MD&A) are being filed today with Canadian securities regulators and will be available at www.sedar.com and on our website at www.freeholdroyalties.com.

Advisories & Contact

Forward-looking Statements

This news release offers our assessment of Freehold’s future plans and operations as at August 2, 2018, and contains forward-looking statements that we believe allow readers to better understand our business and prospects. These forward-looking statements include our expectations for the following:

continuing to position Freehold as a high quality investment in oil and gas with low debt, sustainable dividends and an attractive yield;

foreign exchange rates;

cash costs forecasted at approximately $5.00/boe;

drilling activity during 2018 and the impact on our production base;

our expected adjusted payout ratio for 2018;

average production for 2018, contribution from royalty lands and weighting of oil, NGL and natural gas;

2018 percentage of production and operating income from royalties;

key operating assumptions including operating costs and general and administrative costs;

forecast year-end net debt to funds from operations;

industry drilling and development activity on our royalty lands, including our estimate of 2018 net royalty wells at 20;

our dividend policy and expectations for future dividends; and

maintaining our monthly dividend rate through the next quarter.

By their nature, forward-looking statements are subject to numerous risks and uncertainties, some of which are beyond our control, including the impact of general economic conditions, industry conditions, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, royalties, environmental risks, taxation, regulation, changes in tax or other legislation, competition from other industry participants, the lack of availability of qualified personnel or management, stock market volatility, and our ability to access sufficient capital from internal and external sources. Risks are described in more detail in our AIF.

With respect to forward-looking statements contained in this news release, we have made assumptions regarding, among other things, future commodity prices, future capital expenditure levels, future production levels, future exchange rates, future tax rates, future legislation, the cost of developing and producing our assets, our ability and the ability of our lessees to obtain equipment in a timely manner to carry out development activities, our ability to market our oil and gas successfully to current and new customers, our expectation for the consumption of crude oil and natural gas, our expectation for industry drilling levels, our ability to obtain financing on acceptable terms, shut-in production, production additions from our audit function and our ability to add production and reserves through development and acquisition activities. The key operating assumptions with respect to the forward-looking statements referred to above are detailed in the body of this news release.

You are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Our actual results, performance, or achievement could differ materially from those expressed in, or implied by, these forward-looking statements. We can give no assurance that any of the events anticipated will transpire or occur, or if any of them do, what benefits we will derive from them. The forward-looking information contained in this document is expressly qualified by this cautionary statement. To the extent any guidance or forward looking statements herein constitute a financial outlook, they are included herein to provide readers with an understanding of management’s plans and assumptions for budgeting purposes and readers are cautioned that the information may not be appropriate for other purposes. Our policy for updating forward-looking statements is to update our key operating assumptions quarterly and, except as required by law, we do not undertake to update any other forward-looking statements.

You are further cautioned that the preparation of financial statements in accordance with International Financial Reporting Standards (IFRS), which are the Canadian generally accepted accounting principles (GAAP) for publicly accountable enterprises, requires management to make certain judgments and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses. These estimates may change, having either a positive or negative effect on net income, as further information becomes available and as the economic environment changes.

Conversion of Natural Gas to Barrels of Oil Equivalent (BOE)

To provide a single unit of production for analytical purposes, natural gas production and reserves volumes are converted mathematically to equivalent barrels of oil (boe). We use the industry-accepted standard conversion of six thousand cubic feet of natural gas to one barrel of oil (6 Mcf = 1 bbl). The 6:1 boe ratio is based on an energy equivalency conversion method primarily applicable at the burner tip. It does not represent a value equivalency at the wellhead and is not based on either energy content or current prices. While the boe ratio is useful for comparative measures and observing trends, it does not accurately reflect individual product values and might be misleading, particularly if used in isolation. As well, given that the value ratio, based on the current price of crude oil to natural gas, is significantly different from the 6:1 energy equivalency ratio, using a 6:1 conversion ratio may be misleading as an indication of value.

Non-GAAP Financial Measures

Within this news release, references are made to terms commonly used as key performance indicators in the oil and natural gas industry. We believe that, operating income, operating netback, basic payout ratio, adjusted payout ratio, free cash flow and cash costs are useful supplemental measures for management and investors to analyze operating performance, financial leverage, and liquidity, and we use these terms to facilitate the understanding and comparability of our results of operations and financial position. However, these terms do not have any standardized meanings prescribed GAAP and therefore may not be comparable with the calculations of similar measures for other entities.

Operating income, which is calculated as royalty and other revenue less royalties and operating expenses, represents the cash margin for product sold. Operating netback, which is calculated as average unit sales price less royalties and operating expenses, represents the cash margin for product sold, calculated on a per boe basis.

Payout ratios are often used for dividend paying companies in the oil and gas industry to identify its dividend levels in relation to the funds it receives and uses in its capital and operational activities. Basic payout ratio is calculated as dividends declared as a percentage of funds from operations. Adjusted payout ratio is calculated as dividends paid in cash plus capital expenditures as a percentage of funds from operations.

Free cash flow is calculated by subtracting capital expenditures from funds from operations. Free cash flow is a measure often used by dividend paying companies to determine cash available for payment of dividends, paying down debt or investment.

Cash costs is a total of certain cash expenses in the statement of income deducted in determining funds from operations. For Freehold cash costs are identified as royalty expense, operating expense, general and administrative expense, interest expense and share based compensation payments. It is key to funds from operations, representing the ability to, sustain dividends, repay debt and fund capital expenditures.

We refer to various per boe figures which provide meaningful information on our operational performance. We derive per boe figures by dividing the relevant revenue or cost figure by the total volume of oil, NGL and natural gas production during the period, with natural gas converted to equivalent barrels of oil as described above.

For further information related to these non-GAAP terms, including reconciliations to the most directly comparable GAAP terms, see our most recent MD&A.